In this guide, we'll walk you through the basics of oil and gas production, covering how hydrocarbons are formed, extracted, and processed, as well as the equipment used in these operations.
Use the table of contents to skip to different sections of the learning path.
Many people picture Texas when they think of crude oil production, but the first breakthrough in this fossil fuel came 1500 miles to the northeast.
In 1858, a Dartmouth academic named George Bissel was traveling through rural Pennsylvania when he noticed some locals skimming a dark liquid off the top of a creek.
Bissel took some of the liquid back to Dartmouth and ran tests that showed its potential as a source of fuel.
Bissel saw opportunity. He contacted a local retired railroad conductor, handyman, and jack-of-all-trades named Edwin Drake. The two formed an unlikely partnership around a radical idea: they wanted to drill for oil just like people drilled for water.
After the team secured financing from a banker named James Townsend, Drake set out for the small town of Titusville, Pennsylvania, to go wildcatting.
On Sunday, August 28, 1859 Drake’s driller, William “Uncle Billy” Smith, came out to peer into the well, and saw dark fluid floating on top of the water.
On Monday, when Drake arrived, he found Uncle Billy and his crew standing guard over tubs, washbasins, and barrels filled with oil.
Drake attached a hand pump and began to do exactly what he and Bissel had dreamed about: pump a fuel source up from underground. By the end of 1859, wells had sprung up throughout the new oil country.
The three primary sectors of oil and gas industry are Upstream, Midstream, and Downstream.
Not all formations are created equal. Pay zones and the resource located within them can vary between wells drilled on the same site.
The market value of the resource found in these formations will dictate to the producer if they are worth exploring and producing.
Here are the four types of produced reservoirs in the United States:
This illustration shows us just a sample of the most popular wells being drilled today. Not all well types exist in every production play.
When the natural pressure of a reservoir is no longer strong enough to push the oil to the surface, producers use artificial lift to recover more production.
In this illustration, the producer is using the oldest and most common form: Rod Lift. In rod lift, a pump jack uses sucker rod string and pump to pressurize the well downhole and bring resources up to the surface piping and equipment.
This wellhead is on a dual completed well. In this type of operation, two separate formations are being produced up through the same wellbore and are being controlled at the same wellhead.
This well is in South Texas, and the same type of well can be found throughout Mid-Continent production fields.
Let’s take a trip around a well site and explain what each piece of equipment is doing to separate the oil, gas, and water being produced.
The rod pump is positioned in the well bore where it brings the resource out of the ground and into the well head. This pumping unit attaches to a series of rods, and at the bottom of the rod is a pump. It’s a sleeve with a plunger inside with a check valve ball at the bottom and a check valve at the top.
This emulsion of oil, water, and gas is brought to the surface through the flow line tubing. The production equipment could be near the equipment or in some cases over a mile away before it gets to the processing equipment.
The first vessel the flow line reaches is a 2-phase vertical separator. This separates gas from the water-oil emulsion.
Natural gas, being lighter than liquid, rises to the top of the vessel where it begins to separate from the well stream. The natural gas flows through the outlet on the top of the vessel and into a Kimray back pressure regulator. The back pressure regulator holds constant pressure on the vessels to allow it to move liquids to the next destination.
Any gas over the setpoint will be sent to the meter run to be measured, recorded and sold, typically to a midstream company. The meter run allows the producer to make money from the resources brought to the surface.
Another valve related to the sales line is the flare valve. This back pressure regulator is installed in case there is maintenance on the sales line or if in the future they tie in a new well and pressure backs up on the existing location. The flare valve is set at a higher setpoint than the sale valve. If that pressure setpoint is met, the valve opens sending the gas to a combustor or flare to be incinerated until the condition changes.
The fluid that was brought into the two-phase separator from the flow line is a mix of oil and water. This emulsion drops to the bottom of the vertical separator and is controlled by a liquid level controller. In this setup, a float ball is connected to a dump valve with a mechanical link. As the fluid rises it lifts the float ball in the vessel pushing down on the mechanical linkage which then in turn opens the mechanical dump valve. This allows the oil, water and any solids in the liquid to flow out of the pipe.
This dump line could go directly to a storage tank, but in this case the producer needs to further process the emulsion to make it sellable. It is sent downstream for further processing at the next vessel: a heater treater.
The emulsion flows through the inlet on the top of the heater treater where it hits a baffle. Natural gas still in the fluid begins to separate and flow out of the pipe at the top of the vessel and down to one of two valves. Like in the 2-phase separator, the valves and piping will send the gas either to sales or flare.
The emulsion in the heater treater is funneled through a down comer pipe to the bottom of the vessel surrounding the Fire Tube. Because of the heat from the fire tube, the process fluid molecules relax, allowing the oil and water to separate. Oil is lighter in gravity than water and will float on top of the water.
As it reaches the setpoint, oil comes down the oil outlet pipe to a Kimray weight-operated dump valve, or treater valve. This valve only controls the liquid in the downcomer pipe it does not control the liquid inside the vessel. As the height in the pipe meets the desired level, the valve will open, sending the oil into the storage tank. A midstream company will purchase this crude oil from the producer and transport it to a refinery for further processing.
Salt water is produced when the emulsion is processed with heat from the fire tube. A water siphon is used to control the level of salt water in the vessel. This produced water goes up a pipe into the siphon box, sometimes called a weir box. As the water reaches the siphon nipple, the water spills over and goes down the pipe to another weight-operated dump valve or treater valve.
Again, this valve controls only the level in this downcomer pipe.
When the valve opens, the water goes to either a fiberglass storage tank or on this location, a water treatment plant for further processing.
This is a recirculating line which goes into the recirculating pump. It then goes back to the inlet of the treater to run through the whole process again for more processing.
There are many other pipelines on location, many of them are bypass lines. Some bypass the separator, others bypass the heater treater. There is also a pipeline to bypass both.
To schedule training over Kimray related topics, contact your local Kimray store. Our product and applications trainer can help setup sessions for you or your entire team.
The purpose of all these vessels and Kimray components is to take the raw, unusable products and turn them into important and profitable resources.
An oil emulsion is a mixture of oil, water, and an emulsifying agent.
It contains fine water droplets dispersed in oil. In a crude oil emulsion, the quantity of water droplets is usually less than 10%.
Occasionally, an emulsion occurs that contains droplets of oil dispersed in water. This is called a “reverse emulsion.”
A crude oil emulsion, also called a petroleum emulsion, does not normally exist downhole in a producing formation. Rather, it is formed when oil and water are produced together with a great amount of agitation.
When water and oil in a reservoir enter the well bore through the perforations in the casing, large pressure differences are created which violently mix them together. This forms an emulsion.
While the emulsion travels up the tubing toward the surface, mixing and agitation continue and intensify as gas bubbles are released.
Upon reaching the surface, more violent action takes place as the fluids pass through a choke. Mixing is even more pronounced in pumping or gas lift wells.
In appearance, the emulsion resembles neither oil nor water. For example, a dark green crude oil when emulsified will often appear a muddy brown color.
Generally, the viscosity of the emulsion is higher than the viscosity of the oil or water. In other words, the emulsion is thicker and will not flow as readily as oil or water. It may have a fluffy appearance and feel, which is caused by gas bubbles trapped in the emulsion.
If you looked at the emulsion through a microscope, you would see a great number of tiny spheres of water mixed throughout the oil. Each of these tiny spheres is surrounded by a tough film. This film is a layer of emulsifying agent, and it prohibits the droplets from bumping into one another so they can coalesce.
The emulsifying agent may be naturally occurring elements like paraffin or chemicals used when drilling the well.
Not all of the saltwater produced with the oil is emulsified. The water that is not emulsified is known as free water. Free water will settle quite readily from oil.
If you were to see the inside a separator, it would look like this:
This middle emulsion layer will often remain as an emulsion indefinitely.
An emulsion composed of extremely small droplets that shows no tendency to separate into water and oil is known as a “tight” or “stable” emulsion.
If it is composed of droplets which show a tendency to separate, it is known as a “loose” or “unstable” emulsion.
Emulsifying agents create a film around water droplets and hold it in the oil. The film must be broken in order for the water droplets to coalesce and fall out.
To treat and separate an emulsion, you need something to weaken the film surrounding the water droplets. There are four things that producers use to break the emulsion:
When the film is broken, the water droplets coalesce to form bigger drops, which will settle to the bottom because water is heavier than oil.
Flowback is the first stage of production after a well has been opened. In this guide, we’ll briefly explain the flowback process, the job of a flowback operator, and some unique challenges the flowback phase presents.
The process of producing a well follows six broad stages:
After a well has been drilled, the casing cemented, the shale fractured, the pad laid, and the piping and production equipment installed, the flowback phase begins.
Flowback typically lasts between 30 and 120 days. The fluid produced during this phase is a mixture of crude oil, natural gas, water, and sand.
A producer’s goal during this period is to manage the sandy flowback fluid and keep the well open and running so it can normalize and more freely flow oil and gas.
The fluid first flows up the well bore and through the wellhead, which is often referred to as the “Christmas tree.” From there it moves to sand separators.
Sand separators spin the production fluid, which creates centrifugal force. This is where the bulk of the sand is processed out of the fluid. It is then piped to on-site frac tanks, which trucks will retrieve throughout the process.
Producers then flow the fluid through a variety of separators. These include two- and three-phase separators, free-water knockouts, and heater treaters.
These vessels separate the fluid into its three primary elements—gas, oil, and water. What sand remains sinks to the bottom of the vessels and gets processed out with the water.
Flowback is a very volatile period of production. The pressure is high and sand is ever-present. The key people during this phase are the flowback operators.
A flowback operator is a field professional who specializes in troubleshooting equipment during the flowback phase. His job is to manage this period and keep the well flowing, come what may.
A flowback operator lives in a trailer on site and works twelve hours a day, seven days a week. His primary duties include recording hourly flow rates, troubleshooting equipment, and coordinating transport trucks and equipment techs on site.
We recently had the opportunity to interview a flowback operator on site in the Woodford Shale, and we were able to gather some insight from the challenges he encounters every day.
We’ve been working with flowback operators and oil producers to solve some of the unique challenges flowback production presents. We have found success in three key areas:
The same thing that gives sand its value downhole—its abrasiveness, which is crucial to stimulating shale—presents problems when it comes to the surface during flowback.
Sand flowing at high pressures is destructive. If not managed correctly, it can quickly erode pipes, vessels, and valves.
Due to their tight flow paths, valves are susceptible to damage and must be repaired or replaced regularly during flowback. We’ve seen significant damage done to dump valves in particular.
This led us to test some different solutions to offset this damage. One product that has performed well during flowback is our Piston-Balanced Throttling (PBT) Dump Valve.
With other dump valve options, the trim of the valve sits in the flow path whether the valve is open or closed. During flowback, high-pressure sand is constantly hitting these elements, leading to rapid deterioration.
The PBT Dump Valve pulls the seat, trim, and stem out of the flow path. This means that when the valve opens, the abrasive flowback fluid can dump downstream while causing less damage to the internal valve parts.
Another method some producers have started using is setting up Dual Dump Valves.
This dual set up provides redundancy when maintenance and repairs need to be done. If the trim on one valve fails, you can isolate it and divert the flow to the second valve.
This practice also allows for greater variability in production volume. You can install two smaller valves rather than one large valve.
You can then flow both dump valves in flowback and early high-volume production, and then as the production rate declines move down to one valve and repurpose the other in a different application.
In High Pressure Control Valves, the valve trim is susceptible to damage from abrasive flowback.
While no trim is indestructible, we have two options designed specifically to stand up better to sandy conditions.
During flowback, the composition of a well’s production fluid often changes rapidly. This makes it extremely difficult to maintain accurate liquid level control inside your separator.
The float sitting in the fluid often has a tough time responding to the varying conditions of the fluid. As a result, flowback operators may have to shut-in the vessel and re-weight the float multiple times. This is costly downtime.
To adjust for this, some operators use random items around their site to keep the float up. Adding this weight on the arm can make the float more buoyant to deal with the changing fluid densities.
After noticing this practice, we worked to standardized a solution to help with this issue.
Kimray threaded weights, like those used on our Weight Operated Dump Valves, can be bolted to the trunnion lever bar of the liquid level float. You can quickly adjust or remove these weights as the density of the fluid changes without shutting in the vessel.
Now rather hunting around site for something to weight the float you have a standard, simple solution available to deal with this problem.
Once the well has “cleaned up”—meaning the amount of sand produced has tapered off and production is relatively steady and predictable—the flowback operator turns the well over to the production lease operator.
Artificial lift describes a variety of methods oil and gas producers use to increase downhole pressure and push resources up to the surface.
When a well is first opened, there is typically plenty of existing pressure and volume to get oil and gas to the surface. However, after time that initial boost dwindles. In some areas like the DJ Basin in Colorado, many producers even start new wells with artificial lift to get production flowing strong from the beginning.
Artificial lift is used for two primary reasons:
Some of the most common types of artificial lift are Progressive Cavity Pump (PCP), Rod Lift, Plunger Lift, Gas Lift, Hydraulic Lift, and Electric Submersible Pump (ESP).
The red piece on top is electric motor attached to a gear reduction. A string of rods rotate all the way to where the pump is located. At that point a large screw turns and essentially augers fluid out of the well.
In the picture you can see that the progressive cavity pump is laying horizontally in the well. This is one of the best types of artificial lift for horizontal wells. This is important because all shale plays have horizontal activity.
One challenge for PCP is that has to have electricity to operate. A lot of newer shale plays are in areas that do not have grid power available yet, so they may have to rely on rented generators to power their pump.
The most common example and recognizable method of artificial lift is rod lift.
Rod lift is done using a pump jack at the surface. A pump jack goes by many different terms, including sucker rod pump (SRP), horse head, dinosaur, and nodding donkey.
The pump jack uses sucker rod string and pump to pressurize the well downhole and bring resources up to the surface piping and equipment. The rods don't rotate. They go inside the tubing, which is inside casing. At the bottom of the rod string is a pump and two check valves.
A pump jack may be powered by electricity or gas.
One challenge with rod lift is the volume limitations. If you are operating with increased volumes, you may have to change out the pump, which requires downtime and access to a portable rig.
Plunger lift can be used to create a pressure differential and draw liquid up the casing to production equipment.
This type of artificial lift is done using a timer control, which is typically connected to a High Pressure Control Valve.
There are several different types of plungers, including a solid plunger, pad plunger, brush plunger, and flow through or continuous flow plunger. They all perform a similar function.
As the tubing is shut in, the flow of the well stops. The plunger then falls down to bottom of well, and liquid accumulates on top of it.
The timer tells the control valve to open, and the plunger lifts the column of fluid out, through the valve, then to the production equipment.
Plunger lift is a great option for artificial lift. It's often the first form of artificial lift producers use because they can install it without the large expense of a work-over rig. It's more cost effective than PCP and rod lift, can be set up in a day, requires few people, and doesn't change a lot on location.
An electric actuator is ideal in this situation because pneumatics tend to fail as moisture in the gas causes damage to the elastomers.
Gas lift is another way to lighten the load on the reservoir, which can push the product to the surface.
To employ gas lift, a producer sends low-pressure gas from the well through a compressor. They then send it back down the well. This pressurizes the well and forces liquids back up to the surface piping and equipment.
Gas lift valves sit at calculated depths to inject the high pressure gas into the tubing, which lifts the liquids from that zone.
Gas lift can production ranges widely, from hundreds to several thousand barrels of fluid per day.
Producers also use electric submersible pumps (ESPs) to push production out of the well.
If you live in a rural area and have your own water well, it's more than likely using an ESP.
An ESP sits below the reservoir fluids at the bottom of the tubing string and connects to a long electric motor.
The pump has blades that move the fluids in the well. It is powered electrically, with a cable running from the surface downhole to the pump.
ESPs are designed to move large large volumes of fluid.
They feature a control box (on the right of the ESP in the picture), which can sense when pump needs to be sped up to move more liquids or slowed down as volumes decrease.
One advantage of ESPs is the heat they add.
The friction caused by the pump creates heat. This pre-heats the production fluid and aids in separation even before the fluid gets to the first production vessels. If your fluid is going to a heater treater, you may even be able to lower the burner temperature.
Producers often use a Kimray High Pressure Control Valve package to hold back pressure on the tubing out of the well head. This prevents the pump from causing cavitation.
An ESP can produce over twenty-thousand barrels of fluid per day.
Any time you are working in an oil and gas field, there are hazards you need to be aware of.
In this safety training video for oil and gas, we’ll show you how to spot some of these hazards and take the appropriate action so you go home safe at the end of the day.
We assume you have been granted permission by the operating company and completed their safety training requirements.
Some sites may not have cellular service, so make sure your emergency contacts are aware of your location and estimated time of return.
Before leaving your truck, you want to do three important things to ensure wellsite safety:
You can take a photo of it or record it with paper and pen. This will help in case emergency responders need to find you, and you will need this information for your tailgate safety meeting.
Hydrogen Sulfide is an extremely dangerous byproduct of oil and gas production. It is colorless, flammable, and can quickly cause serious injury if inhaled. If the site you are entering has H2S present, it will be noted at the entrance, which leads us to number 3.
When you turn on your H2S monitor, allow it time to calibrate. Again, H2S is a very hazardous gas that you do not want to ignore. Take this step before stepping on site to protect yourself and your team.
Here are twelve steps to oil and gas safety when you are on site:
When you open the gate, be aware of any cattle or other animals, and be respectful of the owner’s property. Avoid approaching or disturbing any animals on site. Be sure to close the gate after you’ve entered, and when you leave.
Park upwind of the well site to avoid exposure to any potential hazards such as gas leaks or odors. Ensure your vehicle is not obstructing any pathways or access points, allowing for a clear exit if needed.
Make sure everyone is wearing appropriate PPE. This personal protective equipment should include the following at minimum:
Ensure your Hydrogen Sulfide (H2S) monitor is active and positioned correctly within 9 inches of your breathing zone to detect any harmful gas exposure promptly.
Conduct a pre-task meeting to discuss safety protocols and procedures. Identify primary and secondary muster points (assembly areas) upwind in case of emergencies and consider weather conditions affecting safety.
Follow any additional safety procedures required by the lease holder's safety department before entering the site. Attend any mandatory safety briefings to understand site-specific risks.
Always use designated walkways and pathways to navigate around the site. Avoid stepping on berms (raised edges), which may pose trip hazards or potential instability.
Stay vigilant for potential hazards such as slippery surfaces, uneven terrain, or pinch points (areas where you could be caught between moving parts).
Before approaching any equipment or structures, identify and assess obstacles like berms, piping, and walkways to avoid accidents or collisions.
If you detect an oil spill or leakage, stop work immediately and report it to the lease operator. Prompt reporting helps prevent environmental damage and ensures proper cleanup procedures.
Use tools like temperature guns to identify hot surfaces on equipment. Be cautious around vessels or piping that may be hot or under pressure. Assume equipment is hot if unsure.
Approach closed containers or sheds cautiously, watching for potential wildlife like snakes that may pose a danger. Move slowly and carefully to avoid surprises or disturbances.
What are we referring to when we talk about oil?
Crude oil is a black liquid found in geological formations. It is a fossil fuel, which means it is formed from dead organisms that are buried under intense heat and pressure.
But not all crudes are alike. There are three primary qualities that differentiate one oil from another: Weight, Sweetness, and TAN count.
Heavy oil evaporates slowly and contains material that will be used to make heavy products like asphalt.
Light oil requires less processing and produces a greater percentage of gasoline and diesel than heavy oil.
The standard unit of measurement for oil weight is API Gravity. This scale was created by the American Petroleum Institute to measure the density of oil. Below are some visual examples of heavy oil and light oil.
The general rule of thumb to remember is the higher the API, the lighter the oil. The lower the API, the heavier the oil.
You’ve probably heard people referencing “sweet” and “sour” oil.
What makes a particular crude sweet or sour is the amount of sulfur it contains. Sweet crude has very low levels of sulfur, well under 1%. Sour crude has as much as 1-2% of sulfur.
Midstream companies and refiners that transport, store, and process sour oil know they need extra treating capabilities to take out the sulfur and sweeten the product.
TAN stands for “Total Acid Number.” The TAN count of oil is a measure of how corrosive it is.
If a crude has a high TAN number, producers must use more robust metallurgy than standard so their processes can handle that corrosivity and keep the crude in the pipe.
Companies use a test called an assay to get a full chemical breakdown of what is in a barrel of oil. The ideal oil is light and sweet with a low TAN count, while the harder to process oil is heavy and sour with a high TAN count.
There are over one hundred different crude oils traded on the market today.
These oils are typically labeled by the region they come from, and they have a specific chemical makeup. This graph below shows the sulfur content and weight of some of the most common.
The three most well known regional benchmark oils are WTI, Brent, and OPEC.
While logistics also play a role, typically the lighter and sweeter an oil is, the more expensive it’s going to be.
There are four main types of oil and gas reservoirs in the United States today:
Below, we take a high-level trip through the flow path of each of these types to explore the commonly used vessels and equipment.
Standard crude oil reservoirs contain mostly crude oil with minimal amounts of water and gas. Standard oil reservoir will generally have two stages of separation.
The first stage will happen in a Free Water Knockout. In this vessel, retention time will allow the natural specific gravities to start separating the oil, water and gas from each other.
As they exit the vessel:
The second stage separation for an oil reservoir will typically happen in a heater treater. In this vessel, heat is used to accelerate the separation process and continue refining the produced emulsion into its three components.
As they exit the heater treater:
Volatile oil reservoirs contain high amounts of corrosive gas, in addition to oil and water.
This type of reservoir will follow the same path as a standard oil reservoir, except for the gas.
The gas in volatile oil well streams is highly corrosive. Because of this, it must be sent through an additional gas treatment process in a chemical gas conditioning tower or amine unit.
These vessels are designed to absorb unwanted elements from acidic gas. From there, the gas will go to a filter separator to remove any chemical carryover and then go back to the gas sales line.
An important consideration for producers operating volatile oil reservoirs is the materials in their vessels, piping and valves. It is recommended to specify corrosive-resistant materials to prevent premature wear due to the corrosive gas present in this type of well stream.
Dry gas reservoirs produce mostly natural gas with some water vapor.
This type of reservoir will first go through a Gas Production Unit or GPU. This vessel incorporates a line heater and separator in one unit to separate the gas from the liquid.
When leaving the GPU:
If the water content of the gas is too high, a large scrubber is used to remove additional liquid and further clean the gas before traveling into the sales line;
If further separation is needed, it will flow to a gas dehydration unit either at the individual well location or at a central facility before returning to the sales line.
If the quality of the gas is acceptable, but the pressure is too low, a compressor will be used to increase the pressure before it is sent downstream into a sales line.
Gas condensate reservoirs will follow the same path as a dry gas reservoir, except for condensate. Because of the large amounts of condensate these reservoirs produce, additional separation equipment is needed.
After the GPU, the liquid condensate will go to a low-pressure separator to further separate it from the gas.
After that, the condensate will go to storage and the gas will go into a sales line.
